Enhanced Oil RecoveryField Case Studies
James J. ShengBob L. Herd Department of Petroleum Engineering,
Texas Tech University,Lubbock, TX 79409-3111
USA
ELSEVIER
AMSTERDAM • BOSTON • HEIDELBERG • LONDON
NEW YORK • OXFORD • PARIS • SAN DIEGO
SAN FRANCISCO • SINGAPORE • SYDNEY • TOKYO
Gulf Professional Publishing is an imprint of Elsevier
Contents
Preface xix
Contributors xxi
Acknowledgments xxiii
1. Gas Flooding 1
Russell J. Johns and Birol Dindoruk
1.1 What Is Gas Flooding? 1
1.2 Gas Flood Design 2
1.3 Technical and Economic Screening Process 3
1.4 Gas Injection Design and WAG 5
1.5 Phase Behavior 9
1.5.1 Standard (or Basic) PVT Data 9
1.5.2 Swelling Test 9
1.5.3 Slim-Tube Test 10
1.5.4 Multicontact Test 11
1.5.5 Fluid Characterization Using an Equation-of-State 12
1.6 MMP and Displacement Mechanisms 12
1.6.1 Simplified Ternary Representation of DisplacementMechanisms 13
1.6.2 Displacement Mechanisms for Field Gas Floods 15
1.6.3 Determinalion of MMP 15
1.7 Field Cases 16
1.7.1 Slaughter Estate Unit CO, Flood 16
1.7.2 Immiscible Weeks Island Gravity Stable C02 Flood 17
1.7.3 Jay Little Escambia Creek Nitrogen Flood 19
1.7.4 Overview of Field Experience 20
1.8 Concluding Remarks 21
Abbreviations 21
References 22
2. Enhanced Oil Recovery by Using C02 Foams:
Fundamentals and Field Applications 23
S. Lee and S.I. Kam
2.1 Foam Fundamentals 23
2.1.1 Why C02 Is so Popular in Recent Years? 23
2.1.2 Why CO, Is of Interest Compared to Other Gases? 24
2.1.3 Why CQ2 Is Injected as Foams? 24
GD Contents
2.1.4 Foam in Porous Media: Creation and Coalescence
Mechanisms 25
2.1.5 Foam in Porous Media: Three Foam States and Foam
Generation 25
2.1.6 Foam in Porous Media: Two Strong-Foam Regimes—
High-Quality and Low-Quality Regimes 27
2.1.7 Modeling Foams in Porous Media 28
2.1.8 Foam Injection Methods and Gravity Segregation 30
2.1.9 C02-Foam Coreflood Experiments 31
2.1.10 Effect of Subsurface Heterogeneity—Limiting CapillaryPressure and Limiting Water Saturation 32
2.1.11 Foam—Oil Interactions 34
2.2 Foam Field Applications 34
2.2.1 The First Foam Field Applications, Siggins Field, Illinois 34
2.2.2 Steam Foam EOR, Midway Sunset Field, California 35
2.2.3 C02/N2 Foam Injection in Wilmington, California (1984) 37
2.2.4 CCVFoam Injection in Rock Creek, Virginia (1984-1985) 38
2.2.5 C02-Foam Injection in Rangely Weber Sand Unit,
Colorado (1988-1990) 39
2.2.6 C02-Foam Injection in North Ward-Estes,
Texas (1990-1991) 40
2.2.7 C02-Foam Injection in the East Vacuum Grayburg/San Andres Unit, New Mexico (1991 -1993) 42
2.2.8 CCVFoam Injection in East Mallet Unit, Texas, and
McElmo Creek Unit, Utah (1991-1994) 43
2.3 Typical Field Responses During C02-Foam Applications 45
2.3.1 Diversion from High- to Low-Permeability Layers 45
2.3.2 Typical Responses from Successful SAG Processes 46
2.3.3 Typical Responses from Successful Surfactant—Gas
Coinjection Processes 51
2.4 Conclusions 52
Acknowledgment 53
Appendix—Expression of Gas-Mobility Reduction in the Presence
of Foams 53
References 59
3. Polymer Flooding—Fundamentals and Field Cases 63
James ]. Sheng
3.1 Polymers Classification 63
3.2 Polymer Solution Viscosity 64
3.2.1 Salinity and Concentration Effects 64
3.2.2 Shear Effect 65
3.2.3 pH Effect 65
3.3 Polymer Flow Behavior in Porous Media 65
3.3.1 Polymer Viscosity in Porous Media 65
3.3.2 Polymer Retention 67
Contents ( vii )
3.3.3 Inaccessible Pore Volume 68
3.3.4 Permeability Reduction 69
3.3.5 Relative Permeabilities in Polymer Flooding 70
3.4 Mechanisms of Polymer Flooding 70
3.5 Polymer Mixing 72
3.6 Screening Criteria 72
3.7 Field Performance and Field Cases 73
3.7.1 Overall Field Performance 73
3.7.2 Polymer Flooding in a Very Heterogeneous Reservoir 74
3.7.3 Polymer Flooding Using High MW and HighConcentration Polymer 75
3.7.4 Polymer Flooding in Heavy Oil Reservoirs 76
3.7.5 Polymer Flooding in the Marmul Field, Oman 77
3.7.6 Polymer Flooding in a Carbonate Reservoir—Vacuum Field,
New Mexico 78
3.8 Post-Polymer Conformance Control Using Movable Gel 78
References 80
4. Polymer Flooding Practice in Daqing 83
Dongmei Wang
4.1 Mechanism 83
4.1.1 Mobility Control 83
4.1.2 Profile Modification 84
4.1.3 Microscopic Mechanism 86
4.2 Reservoir Screening 87
4.2.1 Reservoir Type 87
4.2.2 Reservoir Temperature 88
4.2.3 Reservoir Permeability 88
4.2.4 Reservoir Heterogeneity 89
4.2.5 Oil Viscosity 90
4.2.6 Formation Water Salinity 90
4.3 Key Points of Polymer Flood Design 91
4.3.1 Well Pattern Design and Combination of Oil Strata 92
4.3.2 Injection Sequence Options 94
4.3.3 Injection Formulation 95
4.3.4 Individual Production and Injection Rate Allocation 101
4.4 Polymer Flooding Dynamic Performance 102
4.4.1 Stages and Dynamic Behavior of Polymer FloodingProcess 102
4.4.2 Problems and Treatments During Different Phases 104
4.5 Surface Facilities 104
4.5.1 Mixing and Injection 105
4.5.2 Produced Water Treatment 106
4.6 A Field Case 107
4.6.1 Well ?a'lern and Oil Strata Combination 107
4.6.2 Polymer Injection Case Design 108
Contenls
4.6.3 Polymer Performance Prediction 109
4.6.4 Polymer Performance Evaluation 111
4.7 Conclusions m
Nomenclature 112
References 114
5. Surfactant-Polymer Flooding 117
James J. Sheng
5.1 Introduction 117
5.2 Surfactants 117
5.2.1 Parameters to Characterize Surfactants 118
5.3 Types of Microemulsions 119
5.4 Phase Behavior Tests 120
5.5 Interfacial Tension 121
5.6 Viscosity of Microemulsion 122
5.7 Capillary Number 122
5.8 Capillary Desaturation Curve 123
5.9 Relative Permeability 123
5.10 Surfactant Retention 124
5.11 SP Interactions 125
5.12 Displacement Mechanisms 126
5.13 Screening Criteria 126
5.14 Field Performance Data 126
5.15 Field Cases 127
5.15.1 Loma Novia Field Low-Tension Waterflooding 127
5.15.2 Wichita County Regular Field Low-Tension
Waterflooding 128
5.15.3 El Dorado M/P Pilot 130
5.15.4 Sloss M/P Pilot 132
5.15.5 Torchlight M/P Pilot 134
5.15.6 Delaware-Childers M/P Project 136
5.15.7 Minas SP Project Preparation 136
5.15.8 SP Flooding in ihe Gudong Field, China 139
References 141
6. Alkaline Flooding 143
James J. Sheng
6.1 Introduction 143
6.2 Comparison of Alkalis Used in Alkaline Flooding 143
6.3 Alkaline Reactions 144
6.3.1 Alkaline Reaction with Crude Oil 144
6.3.2 Alkaline Interaction with Rock 145
6.3.3 Alkaline—Reactions with water 146
6.4 Recovery Mechanisms 146
Contents
6.5 Field Injection Data
6.6 Application Conditions of Alkaline Flooding6.7 Field Cases
6.7.1 Russian Tpexozephoe Field (Abbreviated as Field T)6.7.2 Russian LUarnp-roaeaii Field (Abbreviated as Field W)6.7.3 Hungarian H Field
6.7.4 North Gujarat Oil Field, India
6.7.5 Whirtier Field in California
6.7.6 Torrance Field in California
6.7.7 Wilmington Field in California
6.7.8 Court Bakken Heavy Oil Reservoir in Saskatchewan, Canada
6.8 Conclusions
References
7. Alkaline-Polymer Floodinglames J. Sheng
7.1 Introduction
7.2 Interactions Between Alkali and Polymer7.3 Synergy Between Alkali and Polymer7.4 Field AP Applications
7.4.1 Almy Sands (Isenhour Unit) in Wyoming, USA
7.4.2 Moorcroft West in Wyoming, USA
7.4.3 Thompson Creek Field in Wyoming, USA
7.4.4 David Lloydminster "A" Pool in Canada
7.4.5 Etzikom Field in Alberta, Canada
7.4.6 Xing-28 Block, Liaohe Field, China
7.4.7 Yangsanmu in China
7.5 Concluding Remarks
References
8. Alkaline-Surfactant FloodingJames J. Sheng
8.1 Introduction
8.2 Interactions and Synergies Between Alkali and Surfactant
8.2.1 Alkaline Salt Effect
8.2.2 Effect on Optimum Salinity and Solubilization Ratio
8.2.3 Synergy Between Soap and Surfactant to ImprovePhase Behavior
8.2.4 Effect on IFT
8.2.5 Effect on Surfactant Adsorption8.3 Simulated Results of an Alkaline-Surfactant System8.4 Field Cases
8.4.1 Big Sinking Field in East Kentucky8.4.2 White Castle Field in Louisiana
References
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9. ASP Fundamentals and Field Cases Outside China 189
James ]. Sheng
9.1 Introduction 189
9.2 Synergies and Interactions of ASP 189
9.3 Practical Issues of ASP Flooding 190
9.3.1 Produced Emulsions 190
9.3.2 Chromatographic Separation of Alkali, Surfactant,
and Polymer 191
9.3.3 Precipitation and Scale Problems 192
9.4 Amounts of Chemicals Injected in Chinese Field ASP Projects 192
9.5 Overall ASP Field Performance 194
9.6 ASP Examples of Field Pilots and Applications 194
9.6.1 Lawrence Field in Illinois 194
9.6.2 Cambridge Minnelusa Field in Wyoming 196
9.6.3 West Kiehl Field in Wyoming 198
9.6.4 Tanner Field in Wyoming 199
9.6.5 Lagomar LVA-6/9/21 Area in Venezuela 199
References 200
10. ASP Process and Field Results 203
Harry L. Chang
10.1 Introduction 203
10.2 Background 204
10.3 Laboratory Studies and Mechanistic Modeling 207
10.3.1 Laboratory Studies 207
10.3.2 Mechanistic Modeling 212
10.3.3 Other Laboratory Studies and Field Experiments 215
10.4 The Screening Process 216
10.5 Field Applications and Results 218
10.5.1 ASP Flooding in the Daqing Oil Field 221
10.5.2 ASP Flooding in the Shengli Oil Field 225
10.5.3 ASP Flooding in the Karamay Oil Field 225
10.5.4 Other Field Test Results 226
10.6 Interpretation of Field Test Results 227
10.6.1 Assessment of Oil Recovery Efficiency 227
10.6.2 Interpretation of Recovery Mechanisms 229
10.6.3 Process Application 229
10.7 Lessons Learned 230
10.8 Future Outlook and Focus 232
10.9 Conclusions 235
10.10 Recommendation on Field Project Designs 235
Nomenclature and Abbreviations 239
References 240
Contents GD
11. Foams and Their Applications in EnhancingOil Recovery 251
James J. Sheng
11.1 Introduction 251
11.2 Characteristics of Foam 251
11.3 Foam Stability 252
11.4 Mechanisms of Foam Flooding to Enhance Oil Recovery 257
11.4.1 Foam Formation and Decay 258
11.4.2 Foam Flooding Mechanisms 260
11.5 Foam Flow Behavior 260
11.5.1 Foam Viscosity 260
11.5.2 Relative Permeabilities 261
11.5.3 Mobility Reduction 261
11.5.4 Flow Resistance Factor 262
11.6 Foam Application Modes 262
11.6.1 C02 Foam 262
11.6.2 Steam-Foam 263
11.6.3 Foam Injection in Gas Miscible Flooding 264
11.6.4 Gas Coning Blocking Foam 264
11.6.5 Enhanced Foam Flooding 264
11.6.6 Foams for Well Stimulation 264
11.7 Factors That Need to Be Considered in Designing Foam
Flooding Applications 265
11.7.1 Screening Criteria 265
11.7.2 Surfactants 265
11.7.3 Injection Mode 266
11.8 Results of Field Application Survey 267
11.8.1 Locations of Conducted Foam Projects 267
11.8.2 Applicable Reservoir and Process Parameters 267
11.8.3 Injection Mode 268
11.8.4 Gas Used in Foam 268
11.9 Individual Field Applications 268
11.9.1 Single Well Polymer-Enhanced Foam Flooding Test 268
11.9.2 Nitrogen Foam Flooding in a Heavy Oil Reservoir After
Steam and Waterflooding 271
11.9.3 Snorre Foam-Assisted-Water-Alternating-Gas Project 273
References 276
12. Surfactant Enhanced Oil Recovery in
Carbonate Reservoirs 281
James J. Sheng
12.1 Introduction 281
12.2 Problems in Carbonate Reservoirs 282
GD Contents
12.3 Models of Wettability Alteration Using Surfactants 283
12.4 Upscaling 286
12.5 Oil Recovery Mechanisms in Carbonates Using Chemicals 289
12.6 Chemicals Used in Carbonate EOR 291
12.7 Chemical EOR Projects in Carbonate Reservoirs 292
12.7.1 The Mauddud Carbonate in Bahrain 292
12.7.2 The Yates Field in Texas 29.3
12.7.3 The Cottonwood Creek Field in Wyoming 294
12.7.4 The Baturaja Formation in the Semoga Field
in Indonesia 294
12.7.5 Cretaceous Upper Edwards Reservoir (Central Texas) 295
12.8 Concluding Remarks 296
Nomenclature 296
References 297
13. Water-Based EOR in Carbonates and Sandstones:New Chemical Understanding of the EOR Potential
Using "Smart Water" 301
Tor Austad
13.1 Introduction 301
13.1.1 Wetting in Carbonates 302
13.1.2 Wetting in Sandstones 304
13.1.3 Smart Water Flooding 304
13.2 "Smart Water" in Carbonates 306
13.2.1 Introduction 306
1.3.2.2 Reactive Potential Determining Ions 307
13.2.3 Suggested Mechanism for Wettability Modification 312
13.2.4 Optimization of Injected Water 312
13.2.5 Viscous Flood Versus Spontaneous Imbibitions 315
1.3.2.6 Environmental Effects 315
13.2.7 Smart Water in Limestone 316
13.2.8 Condition for Low Salinity EOR Effects in Limestone 317
13.3 "Smart Water" in Sandstones 320
13.3.1 Introduction 320
13.3.2 Conditions for Low Salinity Effects 320
13.3.3 Suggested Low Salinity Mechanisms 320
13.3.4 Improved Chemical Understanding of the Mechanism 32113.3.5 Chemical Verification of the Low Salinity Mechanism 321
13.4 Field Examples and EOR Possibilities 326
13.4.1 Carbonates 326
13.4.2 Sandstones 328
13.4.3 Statoil Snorre Pilot 330
13.5 Conclusion 332
Acknowledgments 332References
332
Contents
14. Facility Requirements for Implementing a ChemicalEOR ProjectJohn M. Putnam
14.1 Introduction
14.2 Overall Project Requirements14.3 Modes of Chemical EOR Injection
14.3.1 Polymer Flooding14.3.2 Surfactant-Polymer Flooding14.3.3 Alkaline-Polymer Flooding14.3.4 Alkaline-Surfactant-Polymer
14.4 Water Treatment and Conditioning14.5 Handling and Processing EOR Chemicals On-site
14.5.1 Polymer Handling, Processing, and Metering14.5.2 Surfactant Handling and Metering14.5.3 Alkaline Agent Handling.. Processing and Metering
14.6 Injection Schemes and Strategies14.7 Materials of Construction
14.8 Conclusion
References
15. Steam FloodingJames J. Sheng
15.1 Thermal Properties and Energy Concepts15.1.1 Heat Capacity (C)15.1.2 Latent Heat (/.v)
15.1.3 Sensible Heat
15.1.4 Total Volumetric Heat Capacity15.1.5 Thermal Diffusivity (a)
15.1.6 Enthalpy (H, h)
15.1.7 Vapor Pressure, Saturation Pressure, and
Saturation Temperature15.1.8 Steam Quality15.1.9 Temperature-Dependent Oil Viscosity15.1.10 Gravitational Potential Energy15.1.11 Kinetic Energy15.1.12 Total Energy
15.2 Modes of Heat Transfer
15.2.1 Heat Conduction
15.2.2 Heat Convection
15.2.3 Thermal Radiation
15.3 Heat Losses
15.3.1 Heat Loss from Surface Pipes15.3.2 Heat Loss from a Wellbore
15.3.3 Heat Loss to Over- and Underburdon Rocks
15.3.4 Heat Loss from Produced Fluids
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15.4 Estimation of the Heated Area 367
15.5 Estimation of Oil Recovery Performance 370
15.6 Mechanisms 371
15.7 Screening Criteria 371
15.8 Practice in Steam Flooding Projects 373
15.8.1 Formation 373
15.8.2 Injection Pattern and Well Spacing 374
15.8.3 Injection and Production Rates 375
15.8.4 Injection Schemes 376
15.8.5 Time to Convert Steam Soak to Steam Flood 376
15.8.6 Oil Recovery and OSR 377
15.8.7 Completion Interval 377
15.8.8 Production Facilities 378
15.8.9 Water Treatment 378
15.8.10 Monitoring and Surveillance .379
15.9 Field Cases 379
15.9.1 Kern River in California 379
15.9.2 Duri Steam Flood (DSF) Project in Indonesia 381
15.9.3 WASP in West Coalinga Field, CA .382
15.9.4 Karamay Field, China 382
15.9.5 Qi-40 Block in Laohe, China 383
References 386
16. Cyclic Steam Stimulation 389
James J. Sheng
16.1 Introduction 389
16.2 Mechanisms 389
16.3 Estimating Production Response from CSS —Bobergand Lantz Model 391
16.4 Screening Criteria 395
16.5 Practice in CSS Projects 396
16.5.1 General Producing Methods 396
16.5.2 Injection and Production Parameters 397
16.5.3 Completion Interval 400
16.5.4 Wellbore Heat Insulation 400
16.5.5 Incremental Oil Recovery and OSR 400
16.5.6 Monitoring and Surveillance 400
16.6 Field Cases 401
16.6.1 Cold Lake in Alberta, Canada 401
16.6.2 Midway Sunset in California 402
16.6.3 Du 66 Block in the Liao Shuguang Field, China 404
16.6.4 Jin 45 Block in Liaohe Huanxiling Field, China 406
16.6.5 Gudao Field, China 407
16.6.6 Blocks 97 and 98 in Karamay Field, China 408
16.6.7 Gaosheng Field, China 411
References 412
Contents
17. SAGD for Heavy Oil Recovery
ChonghuiShen
17.1 Introduction
17.2 Evaluation of SAGD Resource
1 7.2.1 Importance of Resource Quality17.2.2 Focus of Delineation
17.3 Start-Up17.3.1 Circulation Heating and Inter-Well Communication
Initialization
17.3.2 Well Separation and Start-Up Period
17.3.3 Wellbore Effects
17.4 Well Completion and Work-Over
1 7.4.1 Steam Circulation for Start-Up17.4.2 Thermal Wellbore Insulation
17.4.3 Sand Control Liner
17.4.4 Liner Plugging Issue and Treatment
17.4.5 Recompletion to Fix Local Steam Breakthrough17.4.6 Intelligent Well Completion
17.5 Production Control
17.5.1 Steam Trap17.5.2 Wellbore Lift
17.5.3 Ceysering Phenomenon Under Natural Lift
17.6 Well, Reservoir, and Facility Management1 7.6.1 Wellbore Pressure and Temperature1 7.6.2 Reservoir Monitoring17.6.3 Rock Deformation Evaluation and Surface Monitoring
17.7 SAGD Wind-Down
17.8 Integration of Subsurface and Surface
17.9 Solvent-Enhanced SAGD
References
18. In Situ Combustion
Alex Turta
18.1 Fundamentals
18.1.1 Introduction and Qualitative Description of In Situ
Combustion Techniques18.1.2 Design, Operation, and Evaluation of an ISC Field Project
18.2 Field Applications18.2.1 Screening Guide
18.2.2 Monitoring and Evaluation of an ISC Pilot/Project18.2.3 ISC Pilots
18.2.4 Commercial ISC Projects in Heavy Oil Reservoirs
18.2.5 Wet ISC Projects18.3 ISC Projects in Light Oil Reservoirs
18.3.1 Commercial HPAI Projects in Very Light, Deep,Willislon Basin Oil Reservoirs
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18.3.2 ISC Projects in Waterflooded Reservoirs Containing
Very Light Oil 516
18.3.3 ISC Failures in Reservoirs with Light-Medium Oils 519
18.4 CISC Applications 520
18.4.1 CISC Application for Heavy Oil Production
Stimulation 521
18.4.2 Increase of Injectivity for Water Injection Wells 524
18.4.3 Sand Consolidation by Hot Air Injection("Controlled Coking") 524
18.5 New Approaches to Apply ISC in Combination with
Horizontal Wells 525
18.5.1 Horizontal Wells Drilled in Old Conventional
ISC Projects 525
18.5.2 Long-Distance Versus Short-Distance Displacement 526
18.5.3 THAI Process 528
18.5.4 Other ISC Approaches (COSH and Top-Down ISC) 531
18.6 Operation Problems and Their Remedies 532
18.6.1 Critical Problems 533
18.7 Noncritical Problems 534
' References 536
19. Introduction to MEOR and Its Field Applicationsin China 543
James J. Sheng
19.1 Introduction 543
19.2 MEOR Mechanisms 544
19.3 Microbes and Nutrients Used in MEOR 548
19.4 Screening Criteria 549
19.5 Field Applications 550
19.5.1 Single-Well Microbial Huff-and-Puff 551
19.5.2 Microbial Waterflooding 552
19.5.3 Well Stimulation to Remove Wellbore or
Formation Damage 554
19.5.4 MEOR Using Indigenous Microbes 555
Acknowledgments 558
References 558
20. The Use of Microorganisms to Enhance Oil Recovery 561
Lewis Brown
20.1 Origin of the MEOR Concept20.2 Early Work on MEOR
20.3 Patents on MEOR
20.4 Our Projects on MEOR20.5 Future Studies
References
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Contents
21. Field Applications of Organic Oil Recovery—A NewMEOR Method 581
Bradley Govreau, Brian Marcotte, Alan Sheehy, Krista Town,Bob Zahner, Shane Tapper and Folami Akintunji
21.1 Introduction 581
21.2 Oil Release Mechanism 582
21.3 Discussion of Applications 584
21.3.1 Screening Reservoirs Is Critical to Success 584
21.3.2 Organic Oil Recovery Can Be Applied to a Wide Rangeof Oil Gravities 585
21.3.3 Reservoir Plugging or Formation Damage Is No Longera Risk 587
21.3.4 Microbes Reside in Extreme Conditions and Can Be
Manipulated to Perform Valuable In Situ "Work" 588
21.3.5 Organic Oil Recovery Can Be Successfully Appliedin Dual-Porosity Reservoirs 589
21.3.6 Applying Organic Oil Recovery Can Reduce
Reservoir Souring 590
21.3.7 Organic Oil Recovery Can Be Used in Tight Reservoirs 591
21.3.8 An Oil Response Is Not Always Seen When TreatingProducing Wells 591
21.4 Case Study 1—Trial Field, Saskatchewan 595
21.4.1 Background 595
21.4.2 Reservoir Screening and Laboratory Work 595
21.4.3 Field Application Process 596
21.4.4 Nutrient Test in Producer 596
21.4.5 Pilot 597
21.4.6 Additional Producer Applications 600
21.4.7 Expanding the Pilot 601
21.4.8 Discussion 604
21.5 Case Study 2-Beverly Hills Field, California 604
21.5.1 Background 604
21.5.2 Nutrient Test in Producer 605
21.5.3 Injection Well Treatments 606
21.5.4 Additional Producer Treatments 608
21.5.5 OS-8 609
21.5.6 BH-15 610
21.5.7 Discussion of Results 612
21.6 Conclusion 613
References 613
22. Cold Production of Heavy Oil 615
Bernard Tremblay
22.1 Introduction 616
22.2 Mechanisms 618
Contents
22.2.1 Solution-Gas Drive 618
22.2.2 Sand Production 627
22.3 Field Case645
22.3.1 Heterogeneity of Reservoirs 645
22.3.2 History Matching Cold Production Wells 651
22.3.3 Predicting CHOPS Production 652
22.3.4 Predicting Post-CHOPS Production 656
22.4 Conclusions 660
Acknowledgments662
References662
Index667
